Among the deeper, non-minable deposits of hydrocarbons throughout the world are extensive accumulations of viscous hydrocarbons. In some instances, the viscosity of these hydrocarbons, while elevated, is still sufficiently low to permit their flow or displacement without the need for extraordinary means, such as the introduction of heat or solvents. In other instances, such as in Canada's bitumen-containing oil sands, the hydrocarbon accumulations are so viscous as to be practically immobile at native reservoir conditions. As a result, external means, such as the introduction of heat or solvents, or both, are required to mobilize the resident bitumen and subsequently harvest it.
A number of different techniques have been used to recover these hydrocarbons. These techniques include steam flood, (i.e., displacement), cyclic steam stimulation, steam assisted gravity drainage (SAGD), and in situ combustion, to name a few. These techniques use different key mechanisms to produce hydrocarbons.
Commercially, the most successful recovery technique to date in Canada's oil sands is Steam Assisted Gravity Drainage (SAGD), which creates and then takes advantage of a highly efficient fluid density segregation, or gravity drainage, mechanism in the reservoir to produce oil. A traditional system which is a concomitant of the SAGD process is the SAGD well pair. It typically consists of two generally parallel horizontal wells, with the injector vertically offset from and above the producer.
SAGD was described by Roger Butler in his patent CA 1,130,201 issued Aug. 24, 1982 and assigned to Esso Resources Canada Limited. Since that time, numerous other patents pertaining to aspects and variations of SAGD have been issued. Also, many technical papers have been published on this topic.
The SAGD process, as embodied in the operation of a well pair, and as applied in an oil sand, typically involves first establishing communication between the upper and lower horizontal wells. There are both thermal and non-thermal techniques for establishing this inter-well communication. Subsequent to the establishment of this inter-well communication, steam is injected into the overlying horizontal well on an ongoing basis. Due to density difference, the steam tends to rise and heat the oil sand, and thereby mobilizes the resident bitumen. The mobilized bitumen is denser than the steam, and tends to move downward towards the underlying horizontal well from which it is then produced. By operating the injector and the producer under appropriately governed conditions, it is possible to use the density difference to counteract the tendency of more mobile fluids to channel or finger downward through the less mobile fluids and thereby overwhelm the producing well. Thus, in traditional SAGD operations, each well in the well pair has a specific and distinctive role in ensuring that the efficiencies which can be achieved with a gravity-dominated process are realized.
To achieve this efficiency, and avoid channeling or fingering in conventional SAGD, the flux (i.e., volume rate per unit of well length) must necessarily be limited. Therefore, to restrict the flux and still realize commercial rates, the horizontal wells must be long (e.g., 700 to 1000 meters). This well length requirement poses its own set of problems. Because there are pressure differences along the length of wellbore from heel to toe, flow from the injector into the reservoir and subsequently from the reservoir into the producer is not normally uniform along the length of the wells. This can result in a maldistribution of temperatures, or “hot spots”, along the length of the wells, and can require constraints in operations at the producer to avoid inflow of live steam into the producer.
With respect to the challenge of achieving more beneficial fluid distribution along the length of the horizontal wellbores, numerous configurations have been publicly disclosed. They describe devices and techniques which influence flow geometry by altering or governing the relationship between cross-sectional area to flow, surface area with which the fluids come into contact (i.e., friction), and the change in flow volume along the wellbore as wellbore fluids exit the wellbore and enter the reservoir, or conversely, at specially chosen locations along the length of the wellbore.
Another salient challenge in conventional SAGD operations involves non-condensing gases (NCGs). These evolve or are created within the reservoir during the course of the SAGD process and can interfere seriously with heat transfer between the steam and bitumen. With respect to the challenges of reducing or minimizing the deleterious effects of non-condensing gas in impeding heat transfer between the injected steam and the bitumen, and to means of controlling fluid distribution along the wellbore, the following disclosures have described certain approaches to these problems.
CA 2,618,181 to Struyk et al, assignee FCCL Partnership, and titled “Downhole Steam Injection Splitter” describes a device which singularly or in plurality may be installed along the tubing string of an injection well. The installed module includes a port whose size can be selected or designed to permit injected fluids to exit the well and enter the reservoir at a specified rate for a given set of conditions. A plurality of such modules, each with its individually designed port, can achieve a specific injection (outflow) profile and can, for example, provide a means of achieving uniform flow along the injection wellbore. Struyk is concerned with the profile of fluid distribution of only those fluids exiting the injection wellbore.
U.S. Pat. No. 8,196,661 to Trent et al, assignee Noetic Technologies Inc., and titled “Method for Providing a Preferential Specific Injection Distribution from a Horizontal Injection Well” offers another example of a method and system for governing flow distribution of fluid along the length of a well and subsequent injection of that fluid into the reservoir. As with CA 2,618,181, this disclosure describes a method that uses an injection well only and is concerned with the distribution of flow along that injection wellbore only insofar as that flow exits the wellbore and enters the reservoir. No wellbore configuration or method of well operations is specified in the Noetic patent whereby the injected fluids will then enter the production well in a specified way.
CA 2,769,044 to Butland et al, assignee Alberta Flux Solutions Ltd., and titled “Fluid Injection Device”, describes a device or system for distributing fluids, including steam, along an injection-only wellbore with radially outward flow into the formation. Also, it references devices or approaches which modify the flow resistance within the wellbore to assist in the distribution of injected fluids.
These systems with injection only from the horizontal wellbore into the reservoir are focused on the flow geometry of only the injected fluids into the reservoir without any concern for the flow geometry within the associated production wellbore, or more specifically from the reservoir into the production wellbore.
WO 2013/124744 to Stalder, assignees ConocoPhillips and Total, and titled “SAGD Steam Trap Control”, teaches the use of devices such as those described above in which flow is controlled, but includes both outflow from the injector and inflow into the producer. A key teaching of this patent application is that the horizontal injection and production wells are spaced apart at a vertical distance of 3 meters or less. The use of flow control to restrict the flow of steam vapor is cited. While Stalder mentions the use of flow control devices in both the injector and producer wells, there is no specific geometry in relation to flow control, along and between the wells, that is stipulated.
A follow-up publication by Stalder titled “Test of SAGD Flow Distribution Control Liner System, Surmont Field, Alberta, Canada”, and designated SPE 153706, was presented in Mar. 2012 at the SPE Western Regional Meeting, approximately one month after the priority date of the abovementioned patent application to Stalder. The paper discusses actual field experience in attempting to achieve more uniform distribution of steam within the reservoir and describes the use of ports designed to control the distribution of flow along the length of the wellbores.
A paper titled “Investigation of Key Parameters in SAGD Wellbore Design and Operation” by Vander Valk and Yang, published in the Journal of Canadian Petroleum Technology (JCPT), Jun. 2007, Volume 46, No. 6, presents the results of a comprehensive investigation of pressure distribution along the wellbores and associated well completion methods. The paper recognizes the effects of fluid resistance in the wellbore on SAGD performance. Means of altering fluid resistance in the wellbore, such as choices of tubular diameter, the use of steam ports and limited entry perforations are discussed.
With respect to means of removing unwanted non-condensing gas from the reservoir, CA 2,549,614 encompasses three salient approaches. Specifically, CA 2,549,614 to Nenniger, assignee N-Solv, and titled “Methods and Apparatuses for SAGD Hydrocarbon Production” proposes to move the non-condensing gas away from the active sites within the reservoir where it can interfere with the heat transfer between steam and bitumen. Firstly, it proposes to remove this non-condensing gas component by a convective displacement process involving steam as the displacing agent. Secondly, it proposes the use of a vent well placed within the reservoir so that the non-condensing gases may be vented. Thirdly, it proposes to remove the non-condensing gases from the active steam-bitumen heat transfer site by modifying the buoyancy of the non-condensing gas, for instance by injecting hydrogen.
None of these earlier disclosures, whether related to controlling the distribution of fluids along the length of the well, or whether addressing the issue of non-condensing gases, describes a method and system whereby both the fluid distribution problem and the non-condensing gas problem are beneficially resolved concurrently.